What If Nevada’s Solar Regulators Came to Massachusetts?

What If Nevada’s Solar Regulators Came to Massachusetts?

Last year, thanks to the removal of a tree in my front yard and the confluence of low-cost solar technology and generous state incentives, I put solar on my roof and generated 4 megawatt-hours in my first year as a solar power plant owner.

Everything performed as advertised: the 5.5-kilowatt SunPower system quickly cut my electric bill to $0, then generated a negative balance for most of the summer and fall. December came with a small bill (~$18), but also brought the news from my SREC broker (Knollwood Energy) that SRECs in Massachusetts are trading at $270 per megawatt-hour, so I stood to gain another $1,000 from the system. The 2.99 percent loan I have with EnerBank has a payment of around $189 per month, so if you combine the electric-bill savings with the income from the SRECs, I’m cash flow positive in year 1. 

But, as we’ve covered extensively over the past few weeks here, regulators in Nevada made the unprecedented and alarming decision not only to reform their net-metering program — reducing compensation for exported power coupled with increases in monthly fixed charges — but also to apply the reforms to all existing solar customers in a phased approach over four years.

If regulators in Massachusetts made that same decision today, how would my investment in solar fare over the next 20 years?

It’s worth taking a step back before digging into numbers, because it’s not clear to me how often people think of going solar as a purely economic undertaking. Solar, unlike other home repairs or remodels, feels different, wrapped as it should be in broader impulses to address climate change, energy independence, and overall energy resilience. In that context, the conversation with a solar installer tends toward one that for me felt more trusting (they sell solar, so they must be on my side). With that sense of trust, and the admittedly unfair access to a group of industry-leading market and technology solar analysts here at GTM Research, I went about selecting a solar system with confidence that I would make the right choice, from financing to vendor and installer selection. I honestly never considered that the assumptions around the incentives I would receive might change.

I enlisted the help of EnergySage, a startup near our office in Boston that provides a platform to compare multiple bids from solar installers and attempt to normalize the assumptions behind those bids so I could make the most informed decision.

Over the course of spring 2015, I uploaded all my power bills to the EnergySage platform, filled out all the other information required to receive bids, and within two weeks had about a half dozen. I had already chosen not to lease (I still don’t quite understand why anyone does) so my bids all included the option to pay outright or take out a loan to finance the installation. Throughout the process of reviewing bids, there were many elements of each proposal I needed help understanding (SREC price variability, power production and electric rate increase assumptions, and just what the difference between a DC optimizer and microinverter is), but I certainly understood how the ITC, a state rebate and tax credit, and net metering worked. I knew SREC prices were variable over 10 years, but also that Massachusetts had designed its system well enough to manage that within an acceptable window.

But back to Nevada.

If, in this thought experiment, the Nevada PUC picked up, came to Massachusetts and passed its solar tariff structure here today, what would happen to my electricity bill?

For my system (a SunPower/SolarEdge system purchased in May 2015 at a net cost of around $21,000, which includes the ITC tax benefit and a Massachusetts state rebate), the original benefits of going solar looked like this:

  • 20-year savings on electric bills: $22,759
  • Production incentives: $16,028 (10 years of SRECs, assuming ~$200 for each megawatt-hour generated)
  • Total 20-year benefit: $38,787

With the Nevada plan, my experience would look like this:

  • Ignoring, for now, the possible fluctuations in the SREC market, I would still receive the $16,028 (Go Massachusetts!) because Nevada’s plan doesn’t address anything like SRECs.
  • The impact, therefore, is limited to the saving on electricity bills over 20 years ($22,759). The proposal from my installer, New England Clean Energy, assumes electricity rates start at $0.19 per kilowatt-hour and rise 3 percent annually, so that by year 20 they are around 33 cents per kilowatt-hour. In the Nevada case, these rates may become solar-specific and be reduced by 1 cent. At the same time, monthly fixed charges would rise by around $26.
  • Replace the current net metering scheme with a 4-year step-down from full retail to wholesale compensation, which, as I understand it, would reduce my net metering credit to $0.06 per kilowatt-hour by year 5, and let’s just say it stays that price for the next 15 years (Nevada is actually worse, but whatever).

Jumping out to year 5 — let’s assume my system produces 6,295 kilowatt-hours of solar energy annually and half of it is exported back to the grid and compensated at wholesale rates. Instead of saving $1,346 on the electricity bills as planned, I would save $863 ($674 from load reduction plus $189 for my exported power). Add in annual SREC income of $1,200, and I would have a gross benefit of $2,063.  Subtract my annual cost of the solar loan ($2,156) and the new fixed charges ($300) and I have a negative cash flow. Continue to draw the model out, and I have negative cash flow every year until year 13

If you look at this through the lens of payback on my investment, I don’t reach that until year 19. This is arguably too generous because 1) we have SRECs in Mass, 2) we have higher wholesale rates, and 3) I kept the fixed charges at $300 per year, whereas in Nevada they increase well beyond that over time.

To summarize: my system today is cash flow positive in year 1, and the payback occurs in year 3 if SREC prices remain over $200 per megawatt-hour. If the Nevada PUC came to town, I would have to wait 20 years to break even. I would be 70 years old! Forget it; by then, I’ve moved.

As a homeowner, I took on risk when signing a mortgage for my house at its particular price and interest rate, exposing myself to market fluctuations, tax increases, unforeseen repairs and more. Those were all fairly well-understood risks with precedents and experience.

With my solar system, however, I took risks I understood (SREC variability) as well as those I didn’t (retail rate escalation, service obligations) and placed my trust in the ecosystem of suppliers, installers, the utility and its regulators. This trust is critical for any market to mature, for people on the sidelines to step in and continue to fuel its growth. In the case of Nevada, that trust has clearly been broken.

If other states regard Nevada’s moves as precedent, this becomes much more than a thought experiment for me, but a chilling signal to anyone owning or considering owning rooftop solar. The U.S. residential solar market, which has been celebrating the extension of the ITC, would find itself unfairly hobbled just at the time of its most impressive growth.

Source: greentechmedia.com/GTM_Solar
What If Nevada’s Solar Regulators Came to Massachusetts?

Understanding the Tax Implications of Net Metering Successor Policies

Understanding the Tax Implications of Net Metering Successor Policies

The coming year is likely to be a transitional one for net metering. Last October, the Hawaii Public Utilities Commission decided to phase out its net energy metering program. In December, Nevada followed suit.

The extension of the federal Investment Tax Credit (ITC) will only turbo-charge deployment of customer-sited solar in the coming years, compelling further re-examination of existing distributed generation policies.

As more states consider moving beyond net metering, it is essential to consider the potential tax implications of successor policies.

For this reason, the Clean Coalition conducted an analysis to compare the tax impacts on a typical California homeowner with solar getting compensated under a feed-in tariff (FIT) program compared to net metering.

The Internal Revenue Service has not ruled that energy sold to a utility under a FIT is taxable gross income. However, in this analysis, the Clean Coalition analyzed the implications for the customer-generator if the IRS were to determine that the revenue from energy sales under a FIT constitute taxable gross income.

The result: if energy sales under a FIT are subject to income tax, any tax liability will be offset by the value of applicable tax deductions at a FIT rate up to approximately $0.15 per kilowatt-hour.

Details of the analysis

Under net energy metering (NEM), excess energy is exported to the grid and the customer is credited at the retail rate for each kilowatt-hour delivered. When a NEM system is not producing enough power to meet on-site load, the customer buys power from the electric utility at the retail rate. Under a FIT, a customer-generator sells all power produced to the local utility at a long-term fixed rate and continues to buy all their energy at the retail rate.

Through this analysis, we investigated the tax implications for a California customer-generator who switches to a residential FIT from a NEM program if the IRS were to determine that the FIT energy sales constitute taxable gross income. To do this, we modeled the following: 

  • Electricity consumption and PV generation for a typical California customer
  • Federal and state tax treatments
  • Rate structures for the customer, including the complete compression of California rates from four tiers to two tiers in 2019

The analysis examined impacts on an average Pacific Gas & Electric (PG&E) residential customer located in San Jose, California. We used this location because Santa Clara County, home to the city of San Jose, boasts one of the highest numbers of solar PV and net-metered residential customers in the state — and the most in PG&E’s service territory. 

For this analysis, we assumed the customer-generator owned a 5-kilowatt solar PV system with an annual output of 7,500 kilowatt-hours per year.

We factored in standard federal and California state tax liability, as well as the applicable tax benefits related to either the NEM or FIT program analyzed.


If energy sales under a FIT are subject to income tax, any tax liability will be offset by the value of applicable tax deductions at a FIT rate up to approximately $0.15 per kilowatt-hour for the typical customer, as detailed below.

The extent to which depreciation of a distributed generation (DG) system offsets taxes on energy sales depends on two key variables.

First is the amount of system costs eligible for deduction. If the costs of installing and maintaining the DG system are reduced, then the value of income deductions is lower and vice versa.

The second key variable is the FIT rate. When a lower price is paid for energy, the amount of taxable income is reduced and vice versa.

The National Renewable Energy Laboratory’s System Advisory Model, which we utilized for this investigation, only allowed for analysis of net-metered and buy-all/sell-all FIT systems. However, a middle ground exists and was recently implemented in Hawaii. 

Under this hybrid self-supply plus FIT approach, known in Hawaii as the “grid-supply” option, generation from a customer’s system is first used to satisfy simultaneous on-site load, enabling the customer to avoid purchasing energy at the retail rate from the utility. The customer captures the full value of avoided energy purchases, which may currently be higher than the FIT rate or may become higher over time. Any energy not consumed on-site at the time of generation is sold to the utility at an established FIT rate. The customer continues to buy energy from the utility at the retail rate to meet load not served by the DG system.

Under this hybrid self-supply plus FIT approach, the net present value (NPV) and the payback period would be about halfway between the corresponding FIT and NEM systems. A self-supply plus FIT approach, where the customer sells 50 percent of energy produced, would yield a NPV of approximately $7,829 and a payback period of roughly 7.1 years.

In practice, the results would tend toward the NEM example if daytime load coincided with generation, or toward the FIT example if on-site load did not coincide with generation. Solar panels installed in a more westerly orientation typically support greater matching of generation and load. 

Over the coming years, declining costs of solar PV and changes in applicable rate design, such as the compression of California rates from four tiers to two tiers, will influence the results. We explored potential consequences of these changes by modeling two scenarios: 2015 and 2019. See the full analysis for additional details


John Bernhardt is outreach and communications director at the Clean Coalition. This piece was originally published by the Clean Coalition and is reprinted with permission.

Source: greentechmedia.com/GTM_Solar
Understanding the Tax Implications of Net Metering Successor Policies